To produce oil or gas, a well is drilled into a subterranean formation that is an oil or gas reservoir.
Drilling, completion, and intervention operations can include various types of treatments that are commonly performed in a wellbore or subterranean formation.
For example, a treatment for fluid-loss control can be used during any of drilling, completion, and intervention operations. During completion or intervention, stimulation is a type of treatment performed to enhance or restore the productivity of oil and gas from a well. Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Matrix treatments are performed below the fracture pressure of the formation. Other types of completion or intervention treatments include, but are not limited to, damage removal, formation isolation, wellbore cleanout, scale removal, and scale control. Of course, other well treatments and treatment fluids are known in the art.
Acidizing
A widely used stimulation technique is acidizing, in which a treatment fluid including or forming an aqueous acid solution is introduced into the formation to dissolve acid-soluble materials. This can accomplish a number of purposes, which can be, for example, to help remove residual fluid material or filtercake damage or to increase the permeability of a treatment zone. In this way, hydrocarbon fluids can more easily flow from the formation into the well. In addition, an acid treatment can facilitate the flow of injected treatment fluids from the well into the formation. This procedure enhances production by increasing the effective well radius.
Acidizing techniques can be carried out as matrix acidizing procedures or as acid fracturing procedures. Matrix treatments are often applied in treatment zones having good natural permeability to counteract damage in the near-wellbore area. Fracturing treatments are often applied in treatment zones having poor natural permeability.
In matrix acidizing, an acidizing fluid is injected from the well into the formation at a rate and pressure below the pressure sufficient to create a fracture in the formation. In sandstone formations, the acid primarily removes or dissolves acid soluble damage in the near wellbore region and is thus classically considered a damage removal technique and not a stimulation technique. In carbonate formations, the goal is to actually a stimulation treatment where in the acid forms conducted channels called wormholes in the formation rock.
In acid fracturing, an acidizing fluid is pumped into a carbonate formation at a sufficient pressure to cause fracturing of the formation and creating differential (non-uniform) etching fracture conductivity. Acid fracturing involves the formation of one or more fractures in the formation and the introduction of an aqueous acidizing fluid into the fractures to etch the fractures faces, whereby flow channels are formed when the fractures close. The aqueous acidizing fluid also enlarges the pore spaces in the fracture faces and in the formation. In acid fracturing treatments, one or more fractures are produced in the formation and the acidic solution is introduced into the fracture to etch flow channels in the fracture face. The acid also enlarges the pore spaces in the fracture face and in the formation.
Greater details, methodology, and exceptions regarding acidizing can be found in “Production Enhancement with Acid Stimulation” 2nd edition by Leonard Kalfayan (PennWell 2008), SPE 129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008, IPTC 10693, 66564-PA, and the references contained therein.
The use of the term “acidizing” herein refers to both matrix and fracturing types of acidizing treatments, and more specifically, refers to the general process of introducing an acid down hole to perform a desired function, e.g., to acidize a portion of a subterranean formation or any damage contained therein.
Carbonate Formations
Carbonate formations tend to have complex porosity and permeability variations and irregular fluid flow paths. Even small improvements in recovery methods can yield dramatic production results.
It is desirable to extend the production of wells in carbonate reservoirs and to avoid early abandonment when productivity decreases as a result of formation damage or low natural permeability. In clastic reservoirs, a range of stimulation techniques can be applied with a high degree of confidence to create conductive flow paths, primarily using hydraulic fracturing techniques as known in the field. Although many of these stimulation methods can also be applied in carbonate reservoirs, it may be difficult to predict effectiveness for increasing production from carbonate reservoirs.
Stimulation of carbonate formations usually involves a reaction between an acid and the minerals limestone (CaCO3) or dolomite CaMg(CO3)2 that is intended to enhance the flow properties of the rock. In carbonate reservoirs, hydrochloric acid (HCl) is the most commonly applied stimulation fluid. Organic acids such as formic or acetic acid are used, mainly in retarded-acid systems or in high-temperature applications, to acidize either sandstones or carbonates. Stimulation of carbonate formations usually does not involve hydrofluoric acid, which is difficult to handle and commonly used in acidizing sandstone formations.
Problems with Using Acids in Wells
Although acidizing a portion of a subterranean formation can be very beneficial in terms of permeability, conventional acidizing systems have significant drawbacks. One major problem associated with conventional acidizing treatment systems is that deeper penetration into the formation is not usually achievable because, among other things, the acid may be spent before it can deeply penetrate into the subterranean formation. The rate at which acidizing fluids react with reactive materials in the subterranean formation is a function of various factors including, but not limited to, acid concentration, temperature, fluid velocity, mass transfer, and the type of reactive material encountered. Whatever the rate of reaction of the acidic solution, the solution can be introduced into the formation only a certain distance before it becomes spent. For instance, conventional acidizing fluids, such as those that contain hydrochloric acid, organic acids, or a mixture of hydrochloric and of hydrofluoric acids, have high acid strength and quickly react with the formation itself, fines and damage nearest the well bore, and do not penetrate the formation to a desirable degree before becoming spent. To achieve optimal results, it is desirable to maintain the acidic solution in a reactive condition for as long a period as possible to maximize the degree of penetration so that the permeability enhancement produced by the acidic solution may be increased.
Another problem associated with using acidic fluids is the corrosion caused by the acidic solution to any metals (such as tubulars) in the well bore and the other equipment used to carry out the treatment. For instance, conventional acidizing fluids have a tendency to corrode tubing, casing, and down hole equipment, such as gravel pack screens and down hole pumps, especially at elevated temperatures. The expense of repairing or replacing corrosion-damaged equipment is extremely high. The corrosion problem is exacerbated by the elevated temperatures encountered in deeper formations. The increased corrosion rate of the ferrous and other metals comprising the tubular goods and other equipment results in quantities of the acidic solution being neutralized before it ever enters the subterranean formation, which can compound the deeper penetration problem discussed above. The partial neutralization of the acid results in the production of quantities of metal ions that are highly undesirable in the subterranean formation.
Acid in Oil Emulsions
Historically, water-in-oil emulsified acids have primarily been used in fracture acidizing. The emulsified state of the acid makes it diffuse at much slower rate, thereby retarding the chemical reaction rate with the formation. However, the stability of the emulsion becomes questionable as the fluid experiences high temperature of the formation, that is, equal to or greater than about 121° C. (about 250° F.).
The corrosion inhibition for the tubulars of the well while pumping the acidizing fluid down hole to the treatment zone of a subterranean formation is always an issue.
In addition, the higher the temperature in the tubulars of the well and the higher the design temperature in the treatment zone of the subterranean formation, the greater the rate of corrosion, which increases the rate of damage to the tubulars.
Unfortunately, the compatibility of the corrosion inhibitor with the emulsifier in prior emulsified acidizing fluids is questionable, which significantly affects the temperature stability of emulsion.
The breaking of the emulsion before the targeted time can cause severe corrosion of the tubular.
Acid internal emulsions can be used to help separate the acid from the tubulars, but high concentrations of hydrochloric acid, a commonly used acid for acidizing, can be difficult to stabilize in an emulsion. Halliburton has used fumed silica in the aqueous phase of an emulsified acid system, however, this system and other systems do not provide emulsion stability at higher temperatures, that is, greater than about 121° C. (about 250° F.).
Therefore, among other needs, there is a need for acidizing treatment fluids and methods with acids for stimulation of carbonate formations at high temperatures, that is, equal to or greater than about 121° C. (about 250° F.) while offering minimum protection against corrosion.